Microseismic measurements provide qualitative information about where a fracture stimulation goes. However, there is also quantitative information, which has largely been neglected. We have developed a geomechanical model to predict the extent of shear failure during fracture stimulation of a well. It is a “screening model” meaning point-by-point details of the natural fracture distribution, fluid leakoff, and failure prediction are not emphasized. By matching this to the microseismic cloud of shear failure, we obtain the injection permeability and porosity, which characterize the stimulated reservoir volume (SRV). The model identifies different types of failure, tensile and shear, which will occur on vertical planes of weakness or natural fractures.

The model can be applied to any formation in which the microseismic data demonstrates a substantial spread away from the expected main fracture plane, as occurs in many tight shales. A number of different geometries have been modeled: horizontal vs vertical wells, and transverse vs longitudinal fractures. Not all wells have microseismic data, but the first few wells usually do, and modeling of these cases can provide useful directives for future wells. For example, the injection permeability can provide information on average fracture spacing and aperture width for the induced fracture network (SRV). These can be important for choosing proppant type, size, and concentration for optimal fracture treatments in gas and oil plays in tight shales.

We find the injection permeabilities are relatively high, and these must be associated with fracture-controlled flow. From our case histories, a high injection permeability (>200 md) is required to pressure the formation and achieve failure out as far as the microseismic events extend. Low porosity (≪ 0.1%) is required for the frac fluid to leak off that far. Reports on interference with offset wells support this interpretation. As a case history, the method and results for sequential stimulation of two sister horizontal wells in the Barnett shale are described.

Most of the injection permeability is lost when a well is turned on, and ways to offset this are suggested. One of these ways is to tailor the proppant to the width and spacing of the induced fracture network, to prop more effectively the network of induced fractures. We illustrate some initial guidelines for choosing proppant type, size, and concentration which may improve fracture treatments in tight shales.

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